The more often a utility takes a rate case to its regulators, the more its customers and performance are negatively impacted, according to new metrics.
Traditional cost-of-service ratemaking (COSR) generally requires frequent rate cases and frequent rate cases are statistically associated with poorer utility productivity, according to a new report from Lawrence Berkeley National Laboratory (LBNL). More frequent rate cases are also statistically correlated with higher customer costs, the new metrics reveal.
It is not simply that customers pay the costs of regulatory proceedings, which can be substantial. More significantly, it is that frequent rate cases require a utility to focus on the near term and keep it from seeing the opportunities in innovation that lead to bigger rewards over the long term.
But an emerging form of ratemaking, which rewards utilities for performance the utility and its regulators agree is in the customers' interests, can require less frequent rate cases, according to LBNL’s State Performance-Based Regulation Using Multiyear Rate Plans fo U.S. Electric Utilities.
The researchers argue that performance-based ratemaking (PBR) with multi-year rate plans (MRPs) can be designed to provide stronger incentives for utility innovation and to reduce utility regulatory costs. The result, metrics show, is reduced costs to customers.
The “multifactor productivity" (MFP) growth of the U.S. utility sector was higher than the economy during the early post-WWII period “when favorable business conditions encouraged less frequent rate cases,” the paper reports. MFP growth was “materially slower” than the economy from 1974 to 1985, when rate cases were more frequent.
MFP growth for utilities that go “years without rate cases” is “significantly more rapid,” the researchers also found.
Mark Newton Lowry, Pacific Economics Group (PEG) President for Research and co-author of the LBNL paper, told Utility Dive that PBR with MRPs “is one of the most rapidly growing approaches to alternative regulation in the U.S.”
Flattening electricity demand and competition from customer-sited distributed energy resources (DER) are “only going to get worse for utilities,” Lowry said. Because of COSR, “companies may face deteriorating cost performance just when good cost performance is needed to contend with challenges of distributed generation and storage.”
Ken Costello, Principal Energy and Environment Researcher for the National Regulatory Research Institute (NNRI), wrote recently that a well-designed MRP can forecast conditions that affect rates and rates could then change when those conditions are realized.
Badly designed and implemented MRPs, however, “can wipe out the benefits that potentially would flow to customers,” Costello added.
Shinjini Menon, General Rate Case Director for Southern California Edison (SCE), told Utility Dive that “shorter cycles pose an issue” because rate cases require extensive preparation and can last for months. But longer cycles increase uncertainty because they require “forecasting further into the future.” For SCE, “three-year cycles have worked out fine as a balance,” she said.
Lowry said the report’s metrics show that “utility performance and regulatory cost should be on the radar screen of U.S. regulators, consumer groups and utility managers.”
The multi-year rate plan
The LBNL paper builds on a previous one about PBR and offers “more in-depth analysis of the MRP approach.” It also details “critical plan design issues and challenges.”
The paper starts with why MRPs are useful. It is typically appealing, the paper reports, where regulated utilities face competition or where policymakers want utilities to innovate.
Outside the U.S., a push for MRPs “has often come from policymakers rather than utilities,” the LBNL paper reports. Wide use was made of MRPs in the 1980s for regulated industries where competition was increasing. Electric utility regulators began to use them in California and Northeastern states to spur better performance.
The paper then goes further into why PBR and MRPs are especially useful under current business conditions.
As long as utilities’ load growth provides rising earnings, traditional ratemaking keeps the burden of rate cases down. But utility loads are falling, inflation is anticipated, and utility-scale renewables and distributed energy resources (DER) are proliferating. Together, they threaten to strand the value in older system assets, forcing utilities to go to their regulators more frequently for rate increases.
The MRP in PBR “suspends general rate cases for several years,” the LBNL paper reports. With an MRP, a utility's earning “is to some degree predetermined and independent of a utility’s own cost.”
LBNL focuses on two key MRP strengths. One is that the “rate case moratorium reduces the frequency of rate cases, typically to once every four or five years.” The other is that it has an attrition relief mechanism (ARM) that “escalates rates or revenue between rate cases to address cost pressures such as inflation and growth in number of customers independently of the utility’s own cost.”
With these elements in place, the utility can compete with itself to achieve the designated performance standards. This gives it “an operating environment more like that which competitive markets experience.”
Design elements and metrics
The PBR performance metric is usually based on performance incentive mechanisms (PIMs), which reward or penalize the utility for targeted achievements. PIMs strengthen MRPs because the utility can achieve no reward and may be penalized for poor performance within the MRP term. The MRP may include “earnings sharing mechanisms, efficiency carryover mechanisms, and marketing flexibility,” LBNL adds.
MRPs also drive utility demand side management (DSM) efforts because the results of utility DSM programs are typically tracked, according to LBNL. PIMs can reward utilities for DSM program successes.
With a well-designed MRP, accrued utility benefits can also be shared with customers. And revenue decoupling can free the utility from the need to avoid DSM programs to keep electricity sales high.
NRRI’s Costello described a set of benefits similar to those detailed by LBNL. They include “lower prices, more moderate price changes over time, utility supply of more services, higher reliability and improved customer service, and more immediate price benefits from improved utility performance.”
But regulators must find a “just right” design, Costello cautioned. “The question is: What would it take to produce these benefits?”
MRPs must be designed “to protect customers from excessive rates, to give utilities incentives for cost-efficiency, and to ensure customers that utilities are performing satisfactorily in vital areas such as service quality,” Costello wrote.
Crucially, he added, “when regulators are unable to determine whether a utility’s revenue requirement forecasts reflect prudent management and are unbiased, they should discount the capability of MRPs to benefit customers.”
Lisa Schwartz, the LBNL paper’s project manager and technical editor, stressed that the financial incentive in well-designed MRPs makes utilities “more productive” and “more efficient.” But she also acknowledged “the risk that the design is not quite right and the benefit-sharing between the utilities and the customers may not turn out quite right.”
ARMs are key in MRP design because they address Costello’s concerns, LBNL argues. Price caps can “make utility earnings more sensitive to the kWh and kW of system use, strengthening utility incentives to encourage greater use,” the paper reports. Revenue caps limit “growth in allowed revenue (the revenue requirement).”
Cost trackers allow “expedited recovery of specific utility costs,” the paper adds. They make it “easier for a utility to operate under an MRP.” But they also make the exercise of ARMs easier. Decoupling, performance metric systems, and efficiency carryover mechanisms add to the workability of out-of-rate-case utility operations, LBNL reports.
The complexity of identifying MRP design should not be underestimated, LBNL also reports. “It can be challenging to design plans that strengthen incentives without undue risk and share benefits fairly between utilities and their customers.”
The complexity is difficult for utilities but can be daunting and discouraging for regulators and consumer advocates with small budgets and limited staffing. “If you don’t have the right economists and accountants, that could be problematic,” Schwartz told Utility Dive.
LBNL used two analytic tools to describe “the extra incentive power achieved by MRPs with different plan provisions.”
The numerical analysis of an “Incentive Power Model” compared “the incentive impact of alternative stylized regulatory systems.”
The other analysis was “empirical research” comparing the productivity of U.S. utilities using MRPs and those with “unusually frequent and infrequent rate cases” to U.S. performance norms.
Both analyses found “the frequency of rate cases can materially affect utility cost performance,” LBNL reports.
“Cumulative cost savings of 3% to 10% after 10 years appear achievable under MRPs,” the paper reports.
The utility experience
Utilities regulated by COSR typically have their rates adjusted in a General Rate Case (GRC) to compensate for costs of capital, labor and materials. COSR is effective when conditions “are conducive to realizing at least the target rate of return,” LBNL reports. At those times, utilities face fewer rate cases and “the cost of regulation is quite reasonable.”
When the utility business climate is more difficult, as it currently is, utilities need more frequent GRCs and regulatory costs rise.
The LBNL paper details four cases of U.S. utilities operating for periods of time outside GRCs.
From 1995 to 2013, Central Maine Power (CMP) operated under three succeeding MRPs. ARMs included price caps with escalators that were based on comparisons with other Northeastern utilities’ price and productivity trends. CMP was also given important flexibility in how it marketed to key industrial customers.
In the first approximately 7 years, CMP’s multi-factor productivity (MFP) tracked U.S. utility performance. In subsequent years, CMP’s MFP surpassed the norm.
SCE, San Diego Gas and Electric (SDG&E), and Pacific Gas and Electric (PG&E) have had MRPs since 1986, longer than any other regulated U.S. electric utilities. ARMs include cost trackers, revenue decoupling, some automatic inflation relief, and many other provisions. Importantly, there are also PIMs for implementing demand side management (DSM).
The California utilities successfully implemented DSM and met an array of policy goals between 1986 and 2014. But MFP growth declined by an annual average of 0.14%, while the sampled U.S. electric utility MFP norm growth was 0.43% annually. On query, the IOUs expressed no significant dissatisfaction with MRPs.
SCE has found 3-year rate cases to be preferable, as Menon reported. Besides reducing the utility’s GRC work load without forcing unnecessary uncertainty, it allows test-year operations and spending to be “nearly complete before test-year authorized amounts are available.”
SDG&E spokesperson Colleen Windsor said the utility "supports the adoption of a 4-year GRC term.” It would give utilities and regulators “more flexibility to prepare, review and implement” commission policies. In recent 3-year cycles, she said, “we have not received timely decisions which places a heavy burden on our customers. The 4-year term would reduce the administrative burden on all parties.”
PEG’s Lowry said the Calfornia IOUs represent “the only example we could find of MRPs that actually produce substandard productivity growth.”
New York utilities, on the other hand, represent an example of small productivity growth, while MidAmerican Energy is a significant example of the success MRPs.
Prior to 1994, when MRPs became common, New York utilities’ average MFP growth was 0.98% per year. From 1994 to 2014, with MRPs prevalent, MFP growth averaged 0.54% per year while the national sample average was 0.45% per year. “This is not surprising,” LBNL observes. “New York’s approach to MRP design is conservative, with short rate case cycles.”
MidAmerican Energy has embraced the MRP concept so strongly that it essentially rejects it as it wants to stay out of rate cases permanently.
A 1997 to 2013 rate freeze for the company included multiple ARMs. They included a capital cost tracker, an earnings sharing mechanism, an off-ramp allowing GRCs, if needed, and marketing flexibility. From 1980 to 1995, MidAmerican’s MFP growth fell an average of 1.37% per year. With the rate freeze, its MFP growth grew an average of 1.16% per year. The national sample growth, at 0.42%, was significantly lower.
On the downside, reliability metrics remained stable but did not improve with the freeze and the utility’s record on DSM programs was low.
“We don’t have a multi-year rate plan,” Director of Communications Tina Potthoff told Utility Dive. MidAmerican’s commitment is to “long-term rate stability” and “our goal is to not have rate cases,” she said.
It does not have a formal MRP but, by staying out of GRCs, MidAmerican projects its customers "won’t see a base rate increase until at least 2031,” Potthoff said.
